1. Field of the Invention
The present invention relates to methods and apparatus for determining the velocity of oil flowing in a well. The present invention more particularly relates to the use of optical fluorescence techniques for marking oil flowing in a well.
2. State of the Art
After drilling is completed, in many hydrocarbon wells the borehole is lined with a casing. In order to extract hydrocarbon fluids (oil and gas) from the formation surrounding the borehole, holes are made in the wall of the casing. The location of the holes is usually determined by reference to information acquired about the formation during the drilling operation, and/or after drilling with the aid of logging instruments before the casing is installed.
Various methods are used to urge the fluid out of the formation, into the well, and up to the surface. In most cases, the fluid traveling to the surface is a mixture of two or three fluid components (phases): oil (liquid hydrocarbon), hydrocarbon gas, and water (or brine). The fluid is collected at the surface and is handled in different ways, depending on the relative proportion of each phase. For example, if the fluid contains a relatively small amount of gas, the gas may be burned at the well site since it is not economically practical to process small amounts of gas. If the fluid contains relatively large amounts of water, it may be economically impractical to continue production operations at the site. In fact, even while the well is producing petroleum products, the disposal of water produced from the well is very costly. In general, the different phases of the well fluid enter the well from different locations, and a high water content can be the result of improperly located perforations in the casing. If it is possible to determine where water is entering the well, perforations in the casing can be plugged and the proportional amount of water in the fluid reduced.
The relative volumetric flow rates (flow rate fractions) of the oil, gas, and water through the well is known in the art as the “cut”. The “holdup” is a measure of relative proportions of each phase in a selected volume of fluid in the well; i.e., the volume fraction. The cut and holdup are not in general the same, because the different phases may be, and are in general, flowing at different average speeds. In addition, both the volumetric flow rate and the volume fraction will vary over time and vary at different depths in the well.
Various methods and devices have been used for many years to estimate the volumetric flow rate and the holdup of each phase at different depths in a well over time. Most of the methods of the prior art measure volumetric flow rate or holdup averaged over the cross-sectional area of the wellbore. The principal devices for measuring flow rates employ propellers or turbines which are assumed to measure the average volumetric flow rate of the entire fluid mixture. However, propellers and turbines are typically ineffective in providing even their limited quantitative measurement when the well is not substantially vertical (i.e., when the well deviates more than five degrees from vertical). Other devices of the art measure differential pressure to determine the average density of the flowing mixture. These devices lose their accuracy when fluid flow rate is high or the well is substantially inclined. Still other methods and devices for measuring holdup include the use of electrical plates to measure capacitance of the fluid and make a determination of the fluid content based on variations in capacitance. Similar systems measure resistivity or measure dielectric constant in the presence of RF radiation.
Recent devices derive the wellbore cross-sectional averaged volumetric flow rate and holdup from a number of local measurements made within the wellbore. The accuracy of these averaged volumetric flow rate and holdup determinations depends on the accuracy of each local sensor (probe), the deployment of a sufficient number of probes, and, in the case of non-vertical wells, knowledge of multiphase flow in the inclined pipe. To date, the local sensors which have been used have been mostly electrical sensors which respond to the resistivity of the fluids in the wellbore. However, electrical probes can only measure the holdup and volumetric flow rates of the dispersed phase (e.g., the oil holdup in an oil-water system which is more than about sixty-five percent water).
For continuous phase velocity (liquid system), the method presently considered of choice is to use tracers (sometimes referred to as markers). Continuous phase velocities are particularly important in the high tier market of horizontal wells. A tracer is injected into or created in the flow stream and its arrival downstream is recorded. Typically, the tracer is required to travel approximately ten pipe diameters (or more) to provide a sufficiently well developed flow.
There are at least three well known tracers methods: radioactive tracers, oxygen activation, and a gadolinium tracer. The radioactive tracer consists of a fluid with a relatively short-half life (hours or a few days). A gamma-ray detector is used to measure the velocity via the time-of-flight technique (distance/time). This technique has the disadvantage of requiring the storage, handling, and ejection of a radioactive material.
With oxygen activation, a neutron generator is used to convert stable oxygen into a radioactive isotope of nitrogen. A gamma-ray detector is used to detect the time that the activated material reaches the detector. There is no direct handling of radioactive materials, but the technique has problems with slow velocities and the need for the source-to-detector spacing of ten diameters.
The gadolinium tracer may be used in either a water-soluble or an oil-soluble compound to monitor the respective phase velocities. Because of its extremely high thermal neutron capture cross section, the Gd tracer causes a change in the absorption decay rate of the host phase. A thermal-decay time tool (like the RST-A tool) is used to detect this change as the Gd-doped fluid passes the tool's gamma-ray detectors. This technique requires use of a thermal-decay time tool, thus increasing the cost and complexity of phase velocity acquisition. (Other isotopes such as boron can be used instead of Gadolinium, but the signal-to-noise ratio is much worse).
A fourth tracer technique is disclosed in previously incorporated U.S. Pat. No. 6,016,191 to Ramos et al. According to the '191 patent, a fluorescent tracer is injected at a first location into the flowing fluid, light having a wavelength which causes the fluorescent tracer to fluoresce is introduced into the fluid at a second location, and a detector at the second location which detects light at the fluorescing wavelength is used to determine when the tracer is present. The distance between the locations, and the time it takes from injection of the fluorescent tracer until detection by the detector provides an average fluid velocity. According to the '191 patent, an oil soluble tracer is utilized when oil constitutes the continuous phase of the fluid, and a water soluble tracer is used when water constitutes the continuous phase of the fluid.
Previously incorporated U.S. Pat. No. 6,023,340 to Wu et al. and U.S. Pat. No. 6,075,611 to Dussan et al. also utilize an optical system which measures fluorescence in order to measure oil velocity; albeit without the aid of a tracer. In particular, the '611 patent suggests that light can be injected into a multiphase fluid at a first wavelength which will cause oil to naturally fluoresce at a second wavelength, and that detection of the fluorescence signal over time (and processing of the derivative signal thereof) can be used to obtain information regarding oil drop velocity, flow rate and holdup.
While the techniques described in the previously incorporated patents represent large steps forward in the art, and are useful in most circumstances, there exists at least one particular circumstance when a fluorescing marker or the natural fluorescence of the oil cannot be easily utilized to measure oil velocity. In particular, in a single phase flow of heavy oils, the natural fluorescence cannot be utilized because oil droplets are not distinct. Likewise, the fluorescing marker cannot be easily utilized because the heavy oil is optically opaque, and the fluorescent tracer would have to be present at unacceptably high concentrations to compete for injected photons. In addition, the natural fluorescence of heavy crudes can interfere with the fluorescence measurements of the marker.